Field Test of Cosurfactant-Enhanced Alkaline Flooding

Abstract

Summary A test of cosurfactant-enhanced alkaline flooding, without polymer for mobility control, was conducted in a small reservoir in the White Castle field, Louisiana. Although the flood was unstable, the process recovered at least 38% of the waterflood residual oil in the reservoir as true tertiary oil and exhibited virtually 100% displacement efficiency. Alkali and cosurfactant propagated through the reservoir with acceptable and predictable losses. Introduction To demonstrate that cosurfactant-enhanced alkaline flooding1 is viable in recovering waterflood residual oil from sandstone reservoirs in the near-offshore Gulf of Mexico, a series of tests is being conducted in the White Castle field, Louisiana. The strategy adopted was to pilot the technology in three stages:a flood without polymer to prove features of the process unrelated to achieving mobility control,a test of process polymer injectivity in the same reservoir, anda full process demonstration in a shallower sand. The first phase of the pilot is described in this paper; pilot design, slug formulation, and operations are summarized and key responses are documented and interpreted. Ref. 2 describes the polymer injectivity test. The final pilot stage has not been initiated yet. Pilot Design and Operations Site Selection and Description. After screening of many potential sites, reservoirs in a small fault block in the Wilbert lease of the White Castle field were chosen for the cosurfactant-enhanced alkaline flooding pilot. Key properties of the White Castle reservoirs and their fluids (Table 1) are representative of Shell-owned targets for commercial processes except for the ˜45° dip in the salt dome White Castle reservoirs vs. 0 to 5° dip in the target fields. The difference in this parameter, however, was judged to be less significant because we thought its impact on process performance could be simulated adequately. Other attractive features of the White Castle field included its onshore location, stacked pays (enabling pilots in more than one reservoir with the same wells and surface facilities), proximity to chemical supplies, and infrastructure, all of which made operations less costly than in alternative locations. The reservoirs in the pilot fault block are bounded to the north and south by sealing faults and to the east (updip) by an impermeable shale sheath that drapes the salt dome (Fig. 1). The reservoirs communicate with strong aquifers through a nonsealing fault downdip. The Q sand was initially chosen for the first flood; shallower P and O 1 horizons, which were also deemed suitable, were left as either backups, if subsequent characterization work ruled out the Q sand, or objectives for follow-up pilot phases. Q-Sand Flood Objectives. The goals of the first phase of field testing of cosurfactant-enhanced alkaline flooding were (1) to validate designs of injection facilities; (2) to determine the injectivity of process slugs; (3) to establish the degree of gravity segregation during the process (vertical sweep efficiency); (4) to measure oil recovery, oil cuts, and process displacement efficiency; (5) to measure alkali consumption and surfactant retention; and (6) to gather information on treating produced fluids with conventional production facilities. Well Locations and Functions. To carry out the pilot, a pattern containing a downdip injector; two updip, gas-lifted producers; two logging observers; and a low-fate, rod-pumped sampling well was used (Fig. 1). All the wells used in the operations were drilled specifically for the pilot except the sampler; an existing penetration was recompleted to serve as that well. To obtain detailed petrophysical data on the pilot sands, pressure and rubber sleeve cores were taken when the injector and one of the producers (Well 267), respectively, were drilled. Residual oil saturation (ROS) determinations from core analyses, openhole logs, and a single-well tracer test 3 conducted through Well 267 were remarkably consistent, and the "average" value of 20% was adopted as the residual present in the Q sand. Before the alkaline pilot, Well 85 was the only well ever completed in the Q sand. Consequently, when Well 267 was added updip, it produced oil. To water out Well 267 (and thereby recover mobile oil lying even farther updip that might later compromise pilot interpretation), it was produced at ˜1,250 B/D, a rate more than five times that to be used during most of the pilot operations. During this prepilot attic drawdown, Well 267 produced 12,640 bbl of oil (the first 6,800 bbl at 100% oil cut) and 341,860 bbl of water. Wells 269 and 25, by contrast, both cut 100% water at the time they were completed in the Q sand. The logging observers, Wells 268 and 286, were cased with fiberglass so that process performance could be monitored with gamma spectroscopy, induction, and gamma ray logs. Facilities. Figs. 2 and 3 show the injection and production facilities used for the Q-sand flood. Because the methods of preparing injected fluids and handling produced fluids were unproved, these facilities were designed to provide flexibility for moving process fluids from one area of the facilities to another and with extensive capabilities for sampling and automated data collection. The injection facilities provided (1) storage for ample supplies of slug components, (2) blending and automatic monitoring (pressures, temperatures, pH, conductivities, oxygen content, flow rates, tank levels, and motor on/off condition) equipment, and (3) tanks to maintain a few days' supply of slug. An 02 scavenger (ammonium bisulfite) was added at various points to protect the facilities and well tubulars from corrosion. An on-site laboratory was equipped to perform the wet chemistry analyses needed to confirm that alkali, salt, and cosurfactant concentrations were within tolerances. Throughout the operations, injected fluid compositions were maintained within 5% of specifications, even when the facilities were operated by field personnel with no previous chemical-handling experience. A 30-day period during the drive when 0.4 rather than 1 wt% NaCl was mistakenly injected was the exception. p. 217–223

Review of surfactant-assisted chemical enhanced oil recovery for carbonate reservoirs: challenges and future perspectives

“…Early work on surfactant-alkali flooding was documented in the literature (Mayer et al 1983;McCafferty and McClafin 1992;Falls et al 1994). However, this cEOR technique was mostly carried out in sandstone reservoirs for producing medium and light oils (Wang et al 2010).…”

A review of analogues of alkaline alteration with regard to long-term barrier performance

“…Evidence from alkaline oil floods is shown in Table 3. Results from a deltaic sandstone reservoir in the White Castle Field, Louisiana, USA, using a mixed slug of sodium carbonatesodium silicate solution suggest that scaling of production wells was caused by calcite, rather than silicate mineral precipitation (Falls et al, 1994). Nineteen percent of the total alkali injected (equal to 5.1% of the slug volume) was consumed by reaction in the reservoir.…”

“…The tuffs or mudstones are altered to zeolites, K-feldspar, clay minerals (smectite, celadonite, illite, palygorskite) and silica. The zeolites are mainly analcime, (Falls et al, 1994) Wilmington, California, USA 3 ( 8 610 5 ) Calcite, Mg-silicates and silica. (Krumrine et al, 1985) clinoptilolite, erionite, phillipsite, mordenite and chabazite.…”

Potential for Non-thermal Chemical Augmented Waterflood for Producing Viscous Oils

“…Nelson et al (1984) used a co-surfactant with a higher salinity requirement for Type III phase behavior to address poor alkali propagation and uncertainties in the in-situ soap phase behavior on the fieldscale. Falls et al (1994) reported the recovery of at least 38% of the waterflood residual oil by cosurfactant-enhanced alkaline flooding and without polymer for mobility control at White Castle field. Numerous successful worldwide field-scale chemical flooding (Polymer, SP and ASP) projects have been documented in the literature.…”